WEDNESDAY AGGREGATE: Dynamic Pricing Ascends; Grid-Wide CAISO Dynamics; Interconnection Reforms

Today's briefing examines how:

• Dynamic pricing is shifting from pilot programs to consolidated policy frameworks;
• Gas infrastructure upgrades face new climate-adjusted scrutiny that treats long-term demand decline as the baseline assumption rather than a sensitivity case;
• Transmission balancing accounts reveal increasing volatility driven by grid-wide CAISO dynamics rather than utility-specific costs, making year-ahead forecasting less stable;
• The CAISO's interconnection reforms, while administratively sophisticated, hit their limits in Cluster 15, where deliverability scarcity becomes the binding constraint; and
• PG&E makes a low-key (but significant) move to socialize microgrid project-failure risk, which shifts exposure from utility shareholders to ratepayers.

To some degree, all of these developments are symptoms of a regulatory apparatus adapting to the gap between policy ambition and infrastructure reality.

DYNAMIC PRICING

The CPUC issued an amended scoping memo that consolidates two SCE dynamic pricing applications: for large-power customers (A.24-06-014) and one for general residential and non-residential customers (A.24-12-008).

The proposed Large Power Customer Dynamic Rate has three parts:

• A subscription component, based on the tariff that would otherwise apply to the customer ("Otherwise Applicable Tariff");
• A dynamic component, based on day-ahead hourly market prices and load forecasts, governed by contracts between Edison and individual customers; and
• A non-bypassable charge.

Similarly, Edison's proposed General Dynamic Rate schedule also has three parts:

• A subscription component, based on customers' Otherwise Applicable Tariff;
• A dynamic component, based on day-ahead hourly market prices and load forecasts (applicable only to the portion of the customer's consumption "that is deemed flexible"); and
• An "other" component, including non-bypassable charges and Facilities Related to Demand Charges.

Intervenor testimony is due January 16, 2026, with rebuttal testimony due February 17, 2026.

Instant Analysis: By consolidating SCE’s two applications and anchoring them to the Commission's demand-flexibility framework (established in a decision last August, D.25-08-049), we have another indicator that dynamic rates are moving from pilot-stage experimentation to core rate-design policy.

PG&E GAS COMPRESSOR STATION

The CPUC issued a scoping memo in the proceeding where PG&E seeks a Certificate of Public Convenience and Necessity to replace aging electrical systems at the S-238 Hinkley gas compressor station.

The ruling notes that a draft Initial Study/Mitigated Negative Declaration was issued with a final CEQA document (expected in January 2026), and identifies key issues for litigation, including General Order and Public Utilities Code compliance obligations, environmental review, potential stranded-asset concerns tied to declining gas demand, project cost reasonableness, and public-interest considerations.

Because intervenors questioned whether some electrical components might be linked to gas-throughput needs, PG&E is ordered to submit supplemental testimony itemizing each asset, explaining whether it is affected by compression volumes, and assessing whether any such equipment would still be needed under steep long-term gas-demand decline.

Instant Analysis: By elevating stranded-asset risk, tying asset need to long-term declines in gas throughput, and requiring PG&E to provide granular testimony on whether any electrical components are functionally linked to compression capacity, the CPUC is laying the groundwork for a more exacting review of gas-infrastructure upgrades. The directive to assess each asset’s necessity even under steep gas-demand reductions (more than 40% by 2065) indicates that future CPCNs for gas facilities may face similar climate-adjusted scrutiny.

SDG&E TRANSMISSION

SDG&E filed Advice Letter 4760-E (available here) to notify the CPUC that it has submitted its annual Transmission Access Charge Balancing Account Adjustment (TACBAA) update to FERC, in which it seeks revised transmission revenue requirements and rates effective January 1, 2026.

The TACBAA tracks the difference between CAISO-billed transmission costs and revenues SDG&E receives as a Participating Transmission Owner, and the 2026 update reflects a projected year-end undercollection of $102.8 million, lower forecasted Net Access Charge billings, and adjusted franchise fee/uncollectible estimates, resulting in a total TACBAA credit of $165.8 million (which is significantly lower than the previous year’s $338.1 million credit).

SDG&E proposes a 2026 TACBAA rate of –$0.00993/kWh and requests authority to revise its retail transmission rates upon FERC approval, with changes expected to be consolidated into other January 2026 rate updates for all bundled, Direct Access, and Community Choice Aggregator customers. Protests are due December 10.

Instant Analysis: SDG&E’s TACBAA update highlights how volatile CAISO transmission settlements can rapidly swing a major balancing account from overcollection to undercollection in a single cycle. The $165.8 million credit for 2026 is about half of last year’s, driven mainly by unexpectedly low CAISO revenue credits through October 2025 (an outcome that reverses prior forecasts and tightens the retail offset customers saw in 2025). The smaller proposed TACBAA rate means transmission-related relief on January 1 will be muted compared to last year’s large downward push. For procurement-facing entities, the filing underscores that TACBAA is increasingly sensitive to CAISO-level dynamics rather than SDG&E-specific cost movements, making year-ahead forecasting less stable and more dependent on grid-wide high-voltage transmission revenue signals.

SCE TRANSMISSION

Southern California Edison filed AL 5689-E (available here) to notify the CPUC of its annual updates to the Reliability Services Balancing Account Adjustment (RSBAA) and the Transmission Revenue Balancing Account Adjustment (TRBAA), reflecting corresponding filings made at FERC for 2026.

• The filing shows that SCE’s retail Reliability Services revenue requirement will rise from $8.5 million in 2025 to $9.5 million in 2026, driven mostly by higher Black Start Capability costs.
• Revised RSBAA rates (allocated using 12-Coincident Peak demand and updated for each rate group) show modest increases across nearly all customer classes. SCE also proposes a new TRBAA credit of –$0.00222/kWh, a smaller credit than the current –$0.00271/kWh due to lower forecasted Transmission Revenue Credits.

Beginning January 1, 2026, SCE will combine these updated components with its existing Transmission Access Charge Balancing Account Adjustment to produce a consolidated Transmission Owner Tariff Charge Adjustment for all retail rate schedules. Protests are due December 10.

Instant Analysis: While routine, this filing is a reminder of how even small balancing-account adjustments can stack into year-ahead transmission charges. The RSBAA increase reflects a narrow driver (higher Black Start costs) while the reduced TRBAA credit continues the broader trend of shrinking transmission revenue offsets. None of the changes meaningfully move bills on their own, but together they fold into the January 2026 transmission update cycle that will shape total TAC/Transmission Owner Tariff Charge Adjustment impacts for all customers.

INTERCONNECTION

A new report from Grid Strategies examines how growing transmission scarcity and mounting interconnection backlogs have pushed regional grid operators to adopt various forms of interconnection queue rationing, often through temporary fast-track programs or permanent intake controls that deviate from longstanding open-access principles.

• After outlining the structural causes of congestion (including limited engineering bandwidth, unpredictable upgrade costs, and inadequate proactive transmission planning) the report surveys the rationing mechanisms now in use across PJM, MISO, SPP, and the CAISO, ranging from one-time emergency programs favoring near-term capacity additions to zonal caps and scoring systems aligned with state procurement goals.
• While some of these measures may speed individual projects, the report concludes they risk undermining fairness, transparency, and technology-neutral competition, and argues that long-term solutions must pair readiness-based queue discipline with forward-looking transmission planning that creates deliverability headroom and reduces reliance on ad-hoc rationing constructs.

Regarding the CAISO's Interconnection Process Enhancements (IPE) specifically, the report states:

On balance, CAISO’s IPE represents one of the most comprehensive queue reforms among system operators to date. By combining zonal deliverability caps, scoring-based prioritization, and transparent governance of deliverability allocations, CAISO has replaced an overloaded, speculative queue with a structured pipeline designed to integrate the resources most likely to be financed, built, and aligned with California’s needs.

Yet Cluster 15 [the CAISO’s current interconnection cycle, which experienced severe oversubscription and minimal advancement due to transmission constraints] demonstrates that administrative reforms alone cannot overcome physical infrastructure limits: timelines remain long, the share of projects advancing remains low, and significant low-cost energy potential remains stranded behind constrained transmission corridors. The upcoming refinements under IPE 5.0, particularly around energy-only conversion, long lead-time upgrades, and equitable scoring oversight, will determine whether CAISO can transform this framework into a sustainable, scalable model for integrating the volumes of clean energy required to meet California’s 2030 and 2045 goals.

Instant Analysis: The report frames queue rationing as a symptom of a deeper constraint: the West’s inability to build transmission fast enough to keep pace with project development. The CAISO’s Interconnection Process Enhancements reforms have imposed order on a previously speculative queue, but Cluster 15 shows that process fixes cannot solve physical bottlenecks (deliverability scarcity is now the binding constraint).

MICROGRIDS

PG&E filed an advice letter to revise its Microgrids Balancing Account so that the utility can record and recover expense costs associated with terminated or cancelled Microgrid Incentive Program projects (i.e., costs that would otherwise be written off below the line).

As the Microgrid Incentive Program advances, PG&E argues that two categories of expenses must be captured in a Microgrid Utility Infrastructure Upgrades sub-account:

• Ongoing maintenance for Microgrid Special Facilities; and
• Stranded capital costs from Microgrid Incentive Program projects abandoned due to factors outside PG&E’s control (e.g., construction issues, cost overruns, loss of financing, shifting tax incentives).

Protests are due December 8.

Instant Analysis: This filing is a low-key albeit meaningful move: PG&E is seeking to pre-authorize recovery of stranded microgrid development costs, which shifts the financial risk of failed Microgrid Incentive Program projects from the utility to ratepayers. In other words, the CPUC’s microgrid framework is evolving toward full socialization of project-failure risk, treating cancellations and early terminations as recoverable program expenses rather than utility write-offs. For entities following the Community Microgrid Enablement Program and Microgrid Incentive Program implementation, this is an early indicator of how cost exposure will be allocated as more microgrid pilots encounter practical or financing hurdles.